Calculating fluid distribution in subterranean reservoirs is an important step in determining potential hydrocarbon reserves. As hydrocarbon exploration and production moves to unconventional reservoirs such as complex carbonate formations and shale gas formations, the calculation of the fluid distribution becomes more difficult because of the varying porosity of the rocks in the formation. In particular, microporosity within the formation may cause fluid distribution calculations to be inaccurate.
In gas reservoirs, microporosity will hold most of the water in the formation and most of the water will not flow out of the microporosity, however some gas could be produced and included in the Gas In Place values so as to not underestimate reserves. In oil reservoirs, if a significant amount of oil is held in microporosity, then alternate recovery techniques, such as horizontal drilling and hydraulic fracturing, could be designed to better recover the oil.
Existing methods for calculating fluid distribution in subterranean reservoirs do not take into account the differences between the fluids in macropores and the fluids in micropores. These existing methods may use an average porosity that combines the microporosity and macroporosity or simply ignore the microporosity. When the reservoir under consideration has significant microporosity, such as oil shale reservoirs and shale gas reservoirs, the existing methods may not accurately calculate the fluid distribution.